The invention relates to coiled tubing strings, and in particular to at least partial dual tubing strings, including methods for assembling such strings. More particularly, the invention relates to a cyclic check valve for use in coiled tubing strings.
This invention is tangentially related to U.S. Pat. No. 5,638,904xe2x80x94Safeguarded Method and Apparatus for Fluid Communication Using Coiled Tubing, With Application to Drill Stem Testingxe2x80x94Inventors Misselbrook et al.; PCT Application US 97103.563 filed Mar. 5, 1997 for Method and Apparatus using Coil-in-Coil Tubing for Well Formation, Treatment, Test and Measurement Operationsxe2x80x94Inventors Misselbrook et al; and U.S. Ser. No. 08/564,357 entitled Insulated and/or Concentric Coiled Tubing.
The instant invention relates to apparatus and assembly for at least a partial dual tubing or xe2x80x9ccoil-in-coilxe2x80x9d tubing string, sometimes referred to as PCCT, wherein an inner tubing is sealed within an outer coiled tubing. It is to be understood that although the term coil-in-coil may be used, the xe2x80x9cinner tubingxe2x80x9d need not necessarily be xe2x80x9ccoiled tubingxe2x80x9d, or xe2x80x9ccoiled tubingxe2x80x9d as it is known or practiced today. Standard xe2x80x9ccoiled tubingxe2x80x9d as the xe2x80x9cinner tubingxe2x80x9d does afford a practical solution for first embodiments. The inner tubing, however, could comprise a liner, for instance. Further, there may or may not be an annulus per se defined between the inner and the outer tubing, in whole or in part. Any annulus formed is preferably narrow.
Since providing dual tubing in a string should raise the cost of a string, there may be a cost advantage to minimizing the length of the dual portion. Hence, xe2x80x9cpartialxe2x80x9d coil-in-coil strings, or PCCT, may have cost advantages. A general purpose multi-use partial dual string should have enough dual length to cover the anticipated length of well interval to be serviced. The overall length of the PCCT string will be chosen to service a typical depth range of wells in a particular location. But, coiled tubing may be added or removed from the bottom of the outer coiled tubing string to suit wells outside of the standard depth range. A full dual tubing string, of course, would perform adequately but would be more expensive. Alternately, a partial dual string could be formed by connecting a full dual portion with a single portion. Such a partial dual string could be pre-formed and transported to a job or formed at a job site.
A key purpose for using an at least partial dual string is to provide a protective barrier at the surface to enable safe pumping of well fluids up or down. (Surface is used generally herein to refer to above the wellhead.) To provide this benefit, a dual string has a sealed annulus or the tubings are sealed together, in whole or in part. A dual tubing string annulus preferably would be sealed at or proximate a lower end of the inner tubing, and the seal is preferably located across the annulus between the inner and outer coiled tubing, most preferably within the outer coiled tubing. Preferably also, any annulus would be narrow, to maximize working space. Means can be provided to monitor fluid status, such as fluid flow or pressure, within any annulus formed. A pressurized fluid such as nitrogen could be injected, for instance, into the annulus, or existing fluid within an annulus could be pressured up.
Coiled tubing is commonly utilized in well servicing for working over wells. In a workover, a continuous coiled tubing string is injected into a live well using an associated stuffing box located over the wellhead. Many coiled tubing workovers take place under live well conditions. Coiled tubing has proven particularly useful when working through production tubing or completion tubing.
In normal operations coiled tubing is over-pressured vis a vis well pressure. This insures that were any leaks to develop in the tubing, they would result in flow out of the tubing rather than the reverse, which is important for safety reasons Pressure in the coiled tubing also keeps well fluids from backing up the tubing bore. Well fluids are relegated to the annular space between the coiled tubing and the production tubing or completion tubing. If produced up the annular space outside the coiled tubing, well fluids can be handled in the usual safe manner at a well head.
Fluids pumped down through a coiled tubing string typically enter the tubing at a valve located upon an axle of the reel carrying the string. The fluids run through the remaining tubing wound around the reel, over the gooseneck, down the injector, through the stuffing box, through the wellhead and down the wellbore. Any fluids pumped down a coiled tubing string thus may traverse a significant length of tubing on the surface.
The instant invention anticipates that some live well applications could be more effectively performed with coiled tubing if well fluids were permitted to be circulated up through the tubing rather than up the annulus. For some applications, for instance, the annulus outside of the tubing provides a more effective path for pumping down, leaving the bore for reverse circulating up, e.g., a gravel pack might be more effective if a gravel slurry were pumped down the broader production tubingxe2x80x94coiled tubing annular region than down the narrower coiled tubing bore. Higher circulation rates might be achieved by pumping the slurry down the annulus. This is particularly true because fluid pumped down the bore must pass through a crossover tool near the bottom. Coiled tubing pack-off and crossover tools can be expensive, and the narrow flow paths inherent in miniature tools offer potential sites for blockages. A potential benefit of the proposed system lies in the elimination of the need for complex combination pack-off and crossover tools. Eliminating coiled tubing crossover tools and their associated packers could lead to improved reliability of operations. The proposed system could also alleviate bridging and lead to improved sand pack uniformity.
Another application where a coiled tubing bore offers a more efficient channel for circulating well fluids up a well than the completion-coiled tubing annulus is a well cleanout. Well cleanout requires raising sand, gravel or particulate matter collected at the bottom of a wellhole. Raising particulate matter, without it settling out, necessitates establishing an upward flow velocity that is a certain multiple of the settling velocity of the particles in the liquid. Additional difficulty and complexity occurs when raising particulate matter in deviated wells. As a result quite high flow rates may be needed to effect a sufficient liquid velocity in an annulus to carry particles up. Sometimes the flow rates required are only achievable using the larger sizes of coiled tubing which can be impractical or else uneconomic. Since the annulus between a coiled tubing and completion typically has a larger cross-sectional area than the tubing bore itself, a lesser flow rate pressure would be needed to achieve the same fluid velocity up the bore.
A third live well application for a dual coiled tubing string in accordance with the instant invention lies in using potentially readily available natural gas to unload liquid from live wells. When natural gas is available at a wellhead, from either the same or neighboring wells, such gas may be quite cost effective as a gas lift fluid, However, pumping natural gas down through coiled tubing must be protected at the surface above the wellhead. Personnel and the environment must be safeguarded from leaks that could develop in the coil before the gas passes below the wellhead.
Historically, transporting well fluids at the surface above a wellhead through normal coiled tubing has been deemed hazardous. Such is currently banned for most offshore operations and is generally unacceptable for many land operations. Coiled tubing becomes bent beyond its yield point when moved off a reel and over a gooseneck by an injector. This plastic bending activity typically takes place with a high pressure applied to the interior of the tubing. A pressure differential across the tubing wall during bending increases stress levels in the tubing and accelerates the onset of fatigue cracking. Chemicals used in well operations occasionally tend to pit and corrode tubing material, Chemical corrosion and accumulated fatigue can ultimately lead to small cracks in the wall of the tubing, culminating in a xe2x80x9cpin-holexe2x80x9d in the tubing. While it is possible to limit the incidence of xe2x80x9cpure fatigue pin holesxe2x80x9d by careful management of the fatigue cycles experienced by the tubing, other stress in the tubing can lead to unexpected and premature pin-holes. Today most pin-holes in coiled tubing propagate from stress risers caused by corrosion, the most common cause of such pin-holes being internal pitting from chloride corrosion. Because chlorides are common in the oilfield (seawater, NCI, CaCI, etc.), it is almost impossible to eliminate the possibility of a corrosion pit. The second most common corrosion mechanism is stress corrosion cracking (SCC) arising from exposure to hydrogen sulfide.
A leak of well fluid through a crack or a pinhole in a string between the wellhead and a reel endangers life and the environment. A small hole or crack functions as an atomizer, spraying pressurized fluid from within the tubing to the surroundings above ground. A pooling of leaked gas could be ignited by a spark. Hydrogen sulfide or the like might be contained within the well fluid, to mention another danger.
The crux of the problem with the transportation of well fluids on the surface in coiled tubing is that between the wellhead and the reel valve there is no protective barrier for the crew and the environment against leaks from the tubing. The possibility of leaks is not sufficiently remote. A dual tubing string, or an at least partial coil-in-coil tubing, as taught by the present invention, can cost-effectively provide the needed double barrier to permit well fluids to be safely circulated up or down on the surface through coiled tubing as may be particularly suitable in certain operations.
Since a double barrier is crucial when the well fluids travel between the wellhead and the surface valve, an inner tubing in a dual string should be at least long enough, taking into account the wells and their intended applications, to extend on the surface from a reel connection through a wellhead during the critical pumping or xe2x80x9creverse circulationxe2x80x9d operation.
The instant invention of an at least partial dual tubing string comprises an inner tubing within an outer coiled tubing for at least an upper portion of the string. Preferably the inner tubing is equal to or less than 80% of the length of the outer tubing. Preferably also the outside diameter of the inner tubing is greater than or equal to 80% of the inside diameter of the outer tubing. The inner tubing is sealed against the outer tubing at at least a lower portion of the inner tubing.
In one embodiment a seal is structured to permit some longitudinal movement between an end of the inner tubing and the outer tubing. Preferably the seal is located within the outer tubing. Alternately a seal may fix, or cooperate with an element that fixes. The relative location of an end portion of the inner tubing with respect to the outer tubing.
An upset or stop may be attached or formed onto an inner wall of the outer tubing. The stop may be positioned to limit longitudinal movement of an end of the inner tubing relative to outer tubing. The inner tubing may be inserted such that it is compressed against and biased against the stop within the outer tubing. Preferably any annulus defined between the inner tubing and the outer tubing is quite narrow. The inner tubing could be of the same or of different material as the outer string. Conveniently, the inner tubing could be coiled tubing of slightly smaller diameter. Preferred materials for the inner tubing include aluminum, titanium, beryllium-copper, corrosion resistant alloy materials, plastics with or without reinforcement, composite materials and any other suitable material.
In some embodiments, an inner tubing would run at least xc2xd of the length of the outer tubing, and preferably approximately xc2xc to ⅓ of the length of the outer tubing.
Fluid or pressurized fluid may be inserted in a defined annulus between the tubings and its status or pressure monitored. A fluid, such as nitrogen gas may be provided in the annulus. Changes in the pressure of this annulus fluid would indicate a leak in either the inner tubing or the outer tubing. In either case the well could be shut in and work stopped to maximize the safety of the crew and the environment.
As a further safety measure, a safety check valve may be attached to a lower end of the string. In one embodiment, a cyclic check valve for regulating downhole fluid flow in a coiled tubing string is provided which comprises an outer housing adapted to be connected to a coiled tubing string, the outer housing having a fluid passageway therethrough, and a biased flapper wherein the flapper is biased to close the fluid passageway to prevent fluid flow up through the check valve and into the coiled tubing string. The biasing force acting on the flapper may be overcome to allow fluid flow down through the coiled tubing string and out the check valve. A spring loaded shiftable sleeve is located in the fluid passageway, wherein the sleeve is shiftable by a pressure induced force to cycle the check valve from an activated mode and a de-activated mode, wherein in the activated mode the biased flapper is operable and in the de-activated mode the flapper is inoperable. The check valve also includes a pressure indicator means which will produce a recognizable pressure change when the check valve is cycled between the activated and de-activated modes. In a preferred embodiment, the shiftable sleeve extends through the flapper to prevent the flapper from closing in the de-activated mode. The preferred check valve further comprises a cammed J-slot assembly interconnecting the shiftable sleeve to the outer housing, the J-slot assembly operable to hold the shiftable sleeve in a first position when the check valve is in the activated mode and in a second position when the check valve is in the deactivated mode. The J-slot assembly comprises a cammed J-slot on the outer diameter of the shiftable sleeve and a tracking means, such as a ball, held in place in the inner diameter of the outer housing wherein a portion of the tracking means extends into the J-slot. The J-slot assembly allows for rotational and longitudinal movement of the shiftable sleeve relative to the outer housing as the check valve is cycled between the activated and de-activated modes. In a preferred embodiment, the pressure indicator means produces a pressure drop when the check valve is cycled to the de-activated mode. The pressure indicator means comprising a flow cone which extends into the inlet orifice of the shiftable sleeve to create a flow restriction. The pressure drop is created by movement of the sleeve relative to the flow cone to decrease the size of the flow restriction.
In another embodiment of the invention, a coiled tubing system for circulating fluids in a wellbore is provided comprising a coiled tubing string and a cyclic check valve attached proximate to the leading end of the coiled tubing string. The cyclic check valve comprises an outer housing having a fluid passageway therethrough, a selectively operable valve closure means and a means for cycling the check valve between an activated mode and a de-activated mode, wherein in the activated mode the valve closure means is operable to close the fluid passageway thereby preventing fluid flow up through the check valve and into the coiled tubing string and in the de-activated mode the valve closure means is inoperable to close the fluid passageway, thereby allowing fluid flow up through the check valve and into the coiled tubing string. The cyclic check valve also including a pressure indicator means which will produce a recognizable pressure change when the check valve is cycled between the activated and deactivated modes.
Another aspect of the invention is directed to a method of regulating downhole fluid flow through a coiled tubing string comprising the steps of providing a cyclic check valve proximate to the leading end of the coiled tubing string, positioning the leading end of the coiled tubing string in a wellbore, and selectively cycling the check valve between an activated mode and a deactivated mode, wherein in the activated mode the check valve is operable to prevent the flow of fluid up through the check valve and into the coiled tubing and, in the de-activated mode, fluid may flow up through the check valve and into the coiled tubing. The method also including producing a recognizable pressure response at the surface which indicates the cycling of the check valve between the activated and de-activated modes. The method may further include shifting a shiftable sleeve in the check valve to activate or de-activate a valve closure member in the check valve. The method further comprising providing a pressure induced force to shift the shiftable sleeve to selectively cycle the check valve between the activated and de-activated modes. The method further comprising cycling the check valve to the de-activated mode and reverse circulating fluid up through the cyclic check valve and into the coiled tubing string.
It is possible to construct a xe2x80x9ccompositexe2x80x9d string out of single coil and full or partial coil-in-coil by prejoining them or by delivering both on one spool to a job and joining them together into one string with a connector or a weld as they are being run into the well.
The invention further includes a method for assembling partial coil-in-coil or dual tubing. In one embodiment a tubing string may be assembled by inserting an upper end of an inner tubing into a lower end of an outer tubing and moving the upper end of the inner tubing to an upper end of the outer tubing. This method may include reeling the assembled string onto a first reel and then re-reeling the string onto a second reel. An advantage of such method of assembly is that a directional sliding seal may be attached to the lower end of the inner tubing prior to inserting that lower end into the lower end of the outer tubing. This directional seal may slide relatively easily in one direction, e.g., the direction of insertion, but resist sliding and rather vigorously against the inside wall of the outer tubing when the inner tubing is attempted to be moved in the opposite direction.
In another embodiment, the inner tubing may be welded or connected at its lower end to a sealing section; such as a slip mandrel. The sealing may be lower end to a sealing section, such as a slip mandrel designed to be swaged out, or forced out by a slip, to form a mechanical fixed connection between the tubings. Fluid seals can back up the mechanical connection.
Another method for assembling partial coil-in-coil tubing may include affixing a stop on an inside wall portion of the outer tubing. The stop would be fixed at a location suitable to limit longitudinal motion of an end of an inner tubing within the outer tubing. A stop may be readily introduced on to the flat steel strip at the time of manufacture of the outer coiled tubing string. A stop could be useful if a fixed seal were to be effected between the inner tubing and outer tubing, or if relative movement between the tubings is to be restricted. The inner tubing could be assembled in the outer tubing so as to be compressed against and bias against the stop.
In a further method for assembling a working coiled tubing string, a length of regular coil and a full coil-in-coil length can be welded or connected or delivered to a job unconnected, including on one reel. A single coil and a double coil can be made into one string on a job by manually joining a stringer with a connector as they are run into a well.
Seals may be activated by mechanical means, chemicals, radiation, or heat. The inner tubing may be a liner glued, secured by adhesive, or fused in place. A liner might even be formed in place within the outer tubing.